December 11, 2017 Strategic Expansion into the Core of the Delaware Basin. Two Premier Oil Basins One Efficient, Returns-Focused U.S.

Transcription

1 December 11, 2017 Strategic Expansion into the Core of the Delaware Basin Two Premier Oil Basins One Efficient, Returns-Focused U.S. Oil Company

2 Forward-Looking / Cautionary Statements Forward-Looking Statements This presentation, including the oral statements made in connection herewith, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, derivative instruments, capital expenditure levels and other guidance included in this presentation. When used in this presentation, the words "could," "should," "will, "believe," "anticipate," "intend," "estimate," "expect," "project," the negative of such terms and other similar expressions are intended to identify forward- looking statements, although not all forward-looking statements contain such identifying words. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the headings Risk Factors and Cautionary Statement Regarding Forward-Looking Statements included in the prospectus supplement. These include, but are not limited to, the Company s ability to consummate the acquisition discussed in this presentation, the Company's ability to integrate acquisitions into its existing business, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company's ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company's business and other important factors. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Company s actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Cautionary Statement Regarding Oil and Gas Quantities The Securities Exchange Commission (the SEC ) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities of the exploration and development companies may justify revisions of estimates that were made previously. If significant, such revisions could impact the Company s strategy and future prospects. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, we currently do not disclose probable or possible reserves in our SEC filings. In this presentation, proved reserves at December 31, 201 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-themonth prices of $42.0 per barrel of oil and $2.47 per MMBtu of natural gas. The reserve estimates for the Company at year-end 2010 through 201 presented in this presentation are based on reports prepared by DeGolyer and MacNaughton ("D&M"). We may use the terms that the SEC rules prohibit from being included in filings with the SEC, including "unproved reserves," "EUR per well" and "upside potential," to describe estimates of potentially recoverable hydrocarbons. These are the Company's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities have not been reviewed by independent engineers. Additionally, these quantities may not constitute "reserves" within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or SEC rules and do not include any proved reserves. Estimated ultimate recovery ( EUR ) estimates and drilling locations have not been risked by Company management. Actual locations drilled and quantities that may be ultimately recovered from the Company's interests will differ substantially. There is no commitment by the Company to drill all of the drilling locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, EUR per well and upside potential may change significantly as development of the Company's oil and gas assets provide additional data. Type curves do not represent EURs of individual wells. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 2

3 Strategic and Complementary Expansion into the Core of the Delaware Basin We are acquiring ~20.3K consolidated net acres in the core of the Delaware Basin oil window Acreage located in Loving, Ward and Winkler counties, the deepest part of the play and heart of oil-directed activity Adds 507 net core drilling locations, with material upside Results from our wells and offset operators are among the best in the Delaware Basin November 2017 production of ~3.5 mboe/d (78% is oil, ~$170MM of PDP value) (1) $94 million purchase price will be financed with a mix of common stock and cash (expected Q close) Common Stock issued to sellers (EnCap / Pinebrook): 4 million shares Public Common Stock offering: 32 million shares Remainder to be initially financed with cash from RBL facility Anticipate $500 million of cash proceeds from attractive non-core Williston Basin asset sales Accretive to NAV / share, full-cycle returns and liquidity / leverage (post-asset sales) New Delaware Basin asset is highly complementary to our top-tier Williston Basin position Synergies with our existing operational scale, vertical integration and deep experience in unconventional fullfield development Continuing to drive value in the Williston 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March ) Guidance issued 2/2/15 We Are Now Strategically Positioned in the Core of the Two Best U.S. Oil Basins 1) Assumes 11/30/2017 NYMEX strip pricing 3

4 Returns-Focused, Oil-Weighted, Core-Concentrated and Leveraging Operational Scale Our Williston Asset Core Extended Core Fairway Combined Stats Net Acres (thousand) Williston Delaware PF OAS Our Delaware Asset Core Core Net Inventory (1) Williston Delaware PF OAS Core IRR (2) Williston Delaware PF OAS >75% >75% >75% Active Rigs (3) Williston 5 Delaware [x]f 1 PF OAS Nov Production (mboepd) Williston Delaware PF OAS >72 ~3.5 >75.5 1) 2) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 2014 Operational Scale and Full-field Development Experience Across Our Guidance Leveraging issued 2/2/15 1) 2) 3) Oasis s Williston Basin Inventory as of 12/31/201 Assumes $55 WTI and $3.00 HH Oasis active rigs as of December 1, 2017 Premier Oil Basins with the Objective of Optimizing Capital Efficiency and Full-Cycle Returns 4

5 Summary Transaction Highlights Expands Our Core Inventory Compelling Value Opportunity Leverages Our Existing Operational Scale Adds 507 high-return, oil-weighted and low-risk net core drilling locations Acreage has been materially delineated by the seller and offset operators; results are top tier Multi-stacked pay through known productive formations with inventory upside Selling attractive non-core Williston Basin assets, buying high-return core assets (consolidating into high full-cycle return projects) Establishes a platform for further long-term resource development and returns-focused growth Implied relative valuation below or in-line with most relevant comparable transactions in basin Forge differentiated not only by performance and ultimate resource upside, but also highest oil content vs. peer transactions 100% focused in the core of the Delaware with considerable surrounding well control Purchase price and well economics supportive of very attractive and accretive full-cycle returns Operational scale and experience drives value creation and enhances returns Leverages our full-field development expertise (technical and operational) Oasis management team has extensive Permian Basin experience Material synergies through our select vertical integration (OMS/OMP and OWS) and organizational structure Largely undedicated acreage provides midstream upside Enhances Size, Diversity, and Flexibility Efficiently increases capital allocation opportunities across premier oil basins Enhances overall capital efficiency and shareholder returns 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March ) Guidance issued 2/2/15 Maintains strong balance sheet, liquidity and free cash flow profile 5

6 Core Delaware Basin Assets with Highly Attractive Attributes Key Asset Highlights Premier Position in the Core of the Delaware Advantaged geologic position Deepest part of the Delaware Basin Thick reservoirs with high OOIP Oil-rich and overpressured Ideal for full-scale development Highly contiguous blocks of acreage Ample take-away infrastructure Fits with Oasis s existing strengths Acreage position built for long laterals Largely configured for 2-mile laterals Operated with manageable drilling required for HBP Top-tier well results Recently drilled wells are outperforming offset operators 1.2MMBOE type curve Accomplished strong results with ~1,00 lb/ft completions vs. ~2,000 lb/ft of offset operators Material midstream development opportunities Organic midstream growth opportunities inherent in assets Acreage largely undedicated for hydrocarbon gathering and completely undedicated for water gathering Acquisition Overview Gross Acres (thousands) 40.5 Net Acres (thousands) 20.3 % Operated 90% % Average Core Operated Working Interest 7% 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with November Sanish that 2017 were Production divested in March (boe/d) 2014 ~3,500 2) Guidance issued 2/2/15 Attractive avenue for growth for OMP November 2017 Production % Oil 78%

7 Thick, Multi-Stacked Pay Potential with Large Inventory Upside Formation Type Log (Not to Scale) Development Pattern Wells per DSU Column Thickness Delaware Basin Net Inventory Bone Spring Lime / Avalon + 1,000 1 st Bone Spring nd Bone Spring BS 2 Lower Shale Core Total Potential Locations 3rd Bone Spring Delaware Basin Gross Operated Inventory Wolfcamp A Upper Lower Wolfcamp B Upper Lower Wolfcamp C 250 Core Inventory Additional Upside Total 34 / 5+ 1,200 / 3,800 Core Total Potential Locations 7

8 Oil Cut (%) Contiguous Acreage Blocks Combined with High Oil Cuts Deliver Efficient and Compelling Development Opportunities Summary Highlights Assets in the Deepest and Oiliest Part of the Play Acreage located in the black oil window with high reservoir pressure delivering outstanding well performance results Acreage is located in the deepest and oiliest area of the Delaware basin Continuous formation targets allow long lateral development Approximately 2/3 of identified locations are two-mile laterals Blocky Acreage in Black Oil Window (Wolfcamp A&B) Oily Acreage / Short Laterals Gassy Acreage / Short Laterals Oily Acreage / Long Laterals Gassy Acreage / Long Laterals Lateral Length (ft) Source: IHS Offset operators: APC, CPE, CRZO, CDEV, CVX, XEC, CXO, COP, DVN, FANG, EGN, EOG, XOM, FELIX, HK, JAG, MTDR, NBL, PE, PDCE, Primexx, REN, ROSE, RSPP, ADR, WPX 8

9 Operators Unlocking Formation Targets with Strong Well Performance Lateral 180 IP Rate / Compl Well Name Operator Length Selected Wells Lateral (ft) 180 1,000' IP (Bbls) Rate / Compl Date Well Name Operator 2nd Bone Spring Length (ft) 1,000' (Bbls) Date Ludeman I 3 Ludeman I Well 3 Name RSP 2nd Permian Bone Spring Lateral 7,109 RSP Operator 3rd Permian Bone Spring Length 7,109(ft) 180 IP 8Rate / 1,000' 8(Bbls) 4/1/2017 Compl 4/1/2017 Date Rudd Draw H RSP 2nd 3rd Permian Bone Spring, /29/201 Ludeman Rudd University Draw I Blk H 1H RSP Exxon Permian 7,109,707 7, /29/201 4/1/2017 8/2/201 University Miami Beach Blk H Exxon Cimarex 3rd Bone Spring7,894 4, /2/201 1/3/2017 Rudd Miami University Draw Beach Blk H 1H RSP Cimarex ExxonPermian,707 4,348 3, /29/201 1/14/2015 1/3/2017 University Blk H 1804H Exxon Wolfcamp A 7,894 3, /14/2015 8/2/201 Miami Hughes Beach & Talbot H Cimarex Anadarko Wolfcamp A 4,348 4, /3/2017 1/8/201 University Hughes UL Rock & Of Blk Talbot Ages H H 1H Exxon Anadarko Felix II 10,19 3,25 4, /14/2015 9/21/201 1/8/201 UL Hughes Rock & Of Talbot Ages H 1H Felix Anadarko II Wolfcamp A 10,19 4, /11/201 9/21/201 Hughes UTL & Talbot 1H H Anadarko Jagged Peak 4,821 4,72 9, /11/201 7/29/201 1/8/201 UL UTL University Rock Of Blk Ages 1H H H Felix Jagged ExxonII Peak 10,19 9,99 9, /21/201 7/29/201 8/10/201 Hughes University UTL L. J. & Beldin Blk Talbot H H3H Anadarko Exxon Jagged Peak 4,72 9, 9, /11/201 8/10/201 9/24/201 UTL Caprito L. J. 99 Beldin 302H 1H H Jagged Abraxas Peak 9,99 9,51 4, /11/201 7/29/201 9/24/201 University Caprito RK-Utl 3031B Blk 302H H 1H Exxon Abraxas Jagged Peak 10,432 9, 4, /11/201 11/18/201 8/10/201 UTL RK-Utl University L. 3031B-17 J. Beldin 20-4 Lov H3H 3H Jagged Shell Peak 10,432 9,51 4, /18/201 9/24/201 1/18/201 Caprito University Deuces 99 Wild H Lov 2H 3H Abraxas Shell Anadarko 4,40 4,578 4, /11/201 1/18/201 2/10/201 RK-Utl Deuces UL 21 Bighorn 3031B-17 Wild H 1H2H Jagged Anadarko Forge Energy Peak 10,432 4,723 9, /18/201 2/10/201 5/29/201 University UL Mesquite 21 Bighorn Heat 20-41H Lov 3HUnit 1H Shell Forge Anadarko Energy 4,578 9,400, /31/201 1/18/201 5/29/201 Deuces Mesquite Corbets Wild Heat WA2H Unit 1H Anadarko Callon 4,723,552 9, /31/201 11/27/201 2/10/201 Corbets UL 21 Lead Bighorn King H 2WA 1H Forge Callon Felix IIEnergy 9,400 9,723 4, /27/201 12/31/201 5/29/201 Mesquite UL Lead 21 Pahaska King Heat H Unit 1H 1H Anadarko Felix Forge IIEnergy,552 4,850 4, /31/201 12/31/201 11/7/201 Corbets UL Quinn Pahaska H 1H 2WA Callon Forge WPX Energy 9,723 4,301 4, /27/201 11/7/201 3/17/2017 Quinn UL Lead Yellowtail King 2H H 1H Felix WPX Forge II Energy 4,850 4,780 9, /31/201 3/17/2017 3/1/2017 UL Stella 21 State Pahaska Yellowtail HWRD 1H Forge Shell Energy 4,301 9,512 4, /7/201 1/31/2017 3/1/2017 Quinn Stella State 37 2H WRD 1H 2H WPX Shell Energy 4,780 4, /17/2017 1/31/2017 1/24/2017 Stella UL State Yellowtail Dyk 1H HWRD 2H Shell Forge Energy 9,512 4,770, /24/2017 3/30/2017 3/1/2017 Stella UL 18 State Dyk 1H WRD 1H Shell Forge Energy Wolfcamp B 4,770, * 1/31/2017 3/30/2017 Stella HALEY State H WRD 2H Shell Cimarex Wolfcamp B 4,770 4, /24/2017 9/10/2017 UL HALEY UTL Dyk H 1H 4H Forge Cimarex Jagged Energy Peak 10,321,893 4, /30/2017 9/10/2017 /28/201 UTL H1H Jagged Wolfcamp Peak B 10,321 4, /28/201 3/31/2017 HALEY UTL Mitchell H W101PA 4H Cimarex Jagged Mewbourne Peak 4,928 4,529 4, /10/2017 3/31/2017 2//2017 UTL Mitchell W101PA 1H Jagged Mewbourne Wolfcamp Peak C 10,321 4, /28/201 2//2017 UTL University B20 2H 1W Jagged Mewbourne Wolfcamp Peak C 4,529 4, /31/2017 1/14/2017 Mitchell University 39 B20 W101PA 1W 12 Mewbourne 4,801 4,847 4, /14/2017 3/24/2017 2//2017 University B _W201PA Mewbourne Wolfcamp C 4,585 4, /24/2017 2/25/201 University B20 B21 1W 1_W201PA 8 Mewbourne 4,847 4,551 4, /28/201 1/14/2017 2/25/201 University B20 B Mewbourne 4,585 4, /28/201 3/24/2017 University B20 1_W201PA Mewbourne 4, /25/201 University B21 8 Mewbourne 4, /28/201 Source: IHS, Drilling Info and Public Data. 9

10 Proppant Volumes (lbs/ft) Average Oil Production (bbl/d per 1000') Exceptional Well Performance With Potential Completion Design Upside Summary Highlights Normalized Average Oil Rate (Wolfcamp A & B) (1) Peer-leading well performance Wells flow for extended periods, driving lower LOE costs Bighorn well has been flowing for 18 months Upside potential with further completion optimization Overpressure helps deliver larger volumes over longer periods Offset operators have demonstrated improved well performance by pumping bigger completion volumes (2,000 + lb/ft) Oasis wells have been completed with 1,00 lb/ft, on average Proppant Volumes Benchmark Optimized Completions Potential upside in completion design Lateral Length (ft) Normalized Months Source: IHS 1) Average Oil Rate for Wolfcamp A&B Wells that came online on January 1,201 and forward Offset operators: APC (243), CPE (), CRZO 1), CDEV (85), CVX (18), XEC (205), CXO (223), COP (34), DVN (14), FANG (44), EGN (28), EOG (17), XOM (12), FELIX (11), HK (20), JAG (37), MTDR (49), NBL 84), PE (84), PDCE (25), Primexx (9), REN (24), ROSE (9), RSPP (28), ADR 130), WPX 100)

11 Cumulative Oil Production (Mbo)/1,000' Cumulative Oil Production (Mbo) /1,000' Oasis Well Results are Outperforming Those of Offset Peers Oasis Well Results Outperform Offset Operators (1) Oasis Wells are Outperforming Peer Type Curves 0 Oasis WC A Average 4 Wells 0 All wells still flowing without artificial lift UL 21 Bighorn 1H (WC A) 9,400ft Lateral - (11,90ft TVD) UL 21 Pahaska 1H (WC A) 4,301ft Lateral - (12,142ft TVD) UL 21 Yellowtail 1H (WC A) 9,512ft Lateral - (12,002ft TVD) Offset Operator Type Curve EUR: 1MMbo (1.2 MMboe) UL 18 DYK 1H (WC A),893ft Lateral - (11,401ft TVD) Normalized Months Normalized Months Source: IHS, Peer disclosure 1) Data is defined as Wolfcamp A and B wells in Loving, Reeves, Ward and Winkler counties, with a first production of January 201 or later. Offset operators and well counts used include: ATLANTIC(5), CDEV(14), CXO(25), EOG(5), FELIX II(3), OAS(4), JAG(20), PE(12), RDS(57), RSPP(18) 11

12 $ per Boe $ in Millions Operational Excellence: Demonstrated Capital Efficiency and Low Operating Cost Structure in the Williston Basin Track Record of Efficient Full-Field Development Substantially Improving Capital Efficiency in Core Experienced in full field horizontal development targeting stacked pays $15 $12 $14 $13 $20 $15 Over 750 wells drilled since 2010, averaging ~10,000 feet of lateral length through multiple development zones Vast improvement in drilling times with spud to rig release timing decreasing from 21. days in 2014 to 13. days currently Continuously improving frac efficiency through large pad development around zipper fracs and optimizing logistics $9 $ $3 $- $8.5 $ Base 2014 High Intensity Well Level F&D ($ per Boe) $8 $5 $.8 Current Core Well Cost ($MM) $10 $5 $0 Efficiency and cost-savings through our model of select vertical integration utilizing of OMS, OMP and OWS $12 $10 $8 $ $4 $2 $0 Improving Operating Cost Structure $10.18 $9.34 $7.84 $7.35 $ $5.72 $4.7 $2.80 $2.5 $1.00 $ Q17E E 4Q17E LOE ($/Boe) Differential to WTI ($/Bbl) 12

13 Unique Value and Strategic Opportunities Derived from our Vertically Integrated Platform Oasis Midstream Oasis Well Services Strategic Advantages The acquired acreage is largely undedicated for midstream assets and services Our midstream operations are substantial and growing Adding new platform materially enhances overall portfolio of midstream growth assets Oasis funded midstream capital returned through future drop down potential of retained interest in DevCos Option to develop future projects at OAS and drop to OMP OWS provides material cost-advantages and flexibility, particularly when operating in active basins Opportunity to expand operations into new basin Enhances overall operational scale and intelligence Oil and Natural Gas Gathering & Processing Top tier efficiency Assets and Capabilities Crude Oil Transportation and Storage Freshwater Distribution and Produced Water Gathering and Disposal Two frac spreads running Supply chain management advantage 13

14 Mboepd Update to 2017 and Issuance of 2018 Capital Plan Increasing 4Q17 production guidance from 9-72Mboepd to 71-73Mboepd Combined exit rate for 2018 production of >88 Mboe/d 1 Williston: 83+ Mboepd Delaware: 5 Mboepd Production Highlights 2018 Williston Basin Development Plan Williston Basin Expect to drill and complete 100 to 120 operated wells ~70% WI 5 rigs throughout the year +Non-op activity Current well costs are $.8mm (4mmlb) and $7.7mm (10mmlb) Targeting ~$500mm of non-core asset sales in 2018 Expect to be Free Cash Flow positive on our E&P business at $55 WTI (including Delaware asset) Production Growth Profile Delaware Basin > (1) Expect to drill 1 to 20 wells, complete to 8 wells 1 rig initially with potential to add a second in 2H18 ~$100mm of total capital Minimal outspend at $55 WTI on Delaware asset E 201 Exit 2017E Exit 2018E Exit Williston Delaware 1) Exit rate does not account for potential production loss from anticipated Williston Basin divestitures 14

15 Key Investment Highlights for Oasis Petroleum Operational scale in the two best U.S. oil basins focused on the Core of the North American Core Premier Assets Large, contiguous acreage positions configured for efficient full-field development Extensive inventory of high-return and low-risk drilling locations, supporting attractive development economics across commodity price cycles Concentrated acreage position in the heart of the Williston basin Upside catalysts are near-term and highly visible Vertical integration provides operational flexibility Public midstream MLP a vehicle for growth, liquidity and value illumination Capital efficient and returns focused Disciplined Management Prudently managing balance sheet while being one of the first E&P companies to become free cash flow positive Significant liquidity supported by $1. billion borrowing base 15

16 Appendix 1

17 Sources, Uses and Pro Forma Capitalization Sources & Uses Pro Forma Capitalization (as of 9/30/17) ($ in millions) Sources Equity issued to Seller $43 Equity issued to Public 322 Revolving Credit Facility 11 Total Sources $94 ($ in millions) Expect ~$500mm of proceeds from non-core divestitures Uses Transaction Consideration $94 Total Uses $94 Combined ($ in millions) Standalone Pro Forma Cash and Equivalents $8 $8 Revolving Credit Facility due April 2020 (1) % Senior Notes due Feb % Senior Notes due Nov % Senior Notes due March % Senior Notes due Jan % Convertible Notes due Sep Total debt $2,448 $2,09 Market Value of Equity (2) 2,387 3,172 Enterprise Value $4,827 $5,773 Net Debt $2,439 $2,01 Liquidity: Cash $8 $8 ( ) Letters of credit (10) (10) Borrowing base 1,00 1,00 ( ) Drawn Portion of Revolver (395) (55) Liquidity $1,203 $1,042 Ample liquidity under $1,00mm borrowing base Note: Debt amounts exclude unamortized deferred financing costs and unamortized debt discount. 1) As 11/30/17, we had $333 million of borrowings outstanding under our revolving credit facility, excluding borrowings to pay the $47 million deposit amount for the Acquisition, and had $10.5 million of outstanding letters of credit issued under our revolving credit facility. 2) Based on OAS share price of $10.0 as of 12/8/17. 17